Dual Purpose Radial Drilling Tool String for Cutting Casing and Rock in a Single Trip

ABSTRACT

A downhole apparatus for cutting casing and rock when radial drilling defined by a cutting head that includes three or more cutting edges positioned around the cutting head&#39;s axis of rotation, at least three of the cutting edges in continuous contact with the face of the material being cut, thereby providing lateral and angular stability to the cutting head, one or more internal fluid passageway within the cutting head and one or more orifices for ejecting drilling-fluid out of the cutting head.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present filing claims priority to U.S. provisional patent application 62/285,419 filed on Oct. 29, 2015.

FIELD

The present disclosure generally relates to drilling wellbores into a subterranean formation utilizing short radius lateral drilling. This disclosure has application to oil, gas, water and geothermal wells. More specifically, this disclosure discusses a dual purpose radial drilling tool string capable of cutting casing, cement and rock in a single trip of a radial drilling tool string.

BACKGROUND

Natural resources such as oil and gas located in a subterranean formation can be recovered by drilling a wellbore down to the subterranean formation, typically while circulating a drilling fluid in the wellbore. The wellbore is drilled with the use of a tool string consisting of drill pipe, various tools and having a drill bit on the distal end. During the drilling of the wellbore drilling fluid is typically circulated through the tool string and the drill bit and returns up the annulus between the tool string and the wellbore. After the wellbore is drilled typically the tool string is pulled out of the wellbore and a string of pipe, e.g., casing, can be run in the wellbore. The drilling fluid is then usually circulated downwardly through the interior of the pipe and upwardly through the annulus between the exterior of the pipe and the walls of the wellbore, although other methodologies are known in the art.

Slurries such as hydraulic cement compositions are commonly employed in the drilling, completion and repair of oil and gas wells. For example, hydraulic cement compositions are utilized in primary cementing operations whereby strings of pipe such as casing are cemented into wellbores. In performing primary cementing, a hydraulic cement composition is pumped into the annular space between the walls of a wellbore and the exterior surfaces of the casing. The cement composition is allowed to set in the annular space forming an annular sheath of hardened substantially impermeable cement. This cement sheath physically supports and positions the casing relative to the walls of the wellbore and bonds the exterior surfaces of the casing string to the walls of the wellbore. The cement sheath prevents unwanted migration of fluids between zones or formations penetrated by the wellbore.

The drilling of a horizontal well typically involves the drilling of an initial vertical well and then a lateral extending from the vertical well which arcs as it deviates away from vertical until it reaches a horizontal or near horizontal orientation into the subterranean formation.

In short radius drilling specialized tools are swept around a tight radius of a whipstock and are then used to form lateral boreholes radiating outward and into the subterranean formation. Short radius lateral drilling is distinct from more-familiar conventional horizontal and coil tubing drilling. In conventional horizontal and coil tubing drilling procedures, the drilling tools are swept around a radius or “heel” that is hundreds or even thousands of feet in size. That is, in both of these procedures virtually all of the change in direction takes place outside of the wellbore proper. By contrast, in short radius drilling, the primary change of direction occurs inside of the wellbore itself—that is, it occurs literally in the matter of a few inches.

As wellbores suited to this procedure commonly have a diameter of between about 4½″ to 7″, this equates to radii of between about 2¼″ to about 3½″ inches. In many short radius lateral drilling procedures a full 90 degree arc or “heel” is completed within the wellbore—that is, within about 0.25 ft (3 inches). This contrasts markedly with coiled tubing drilling, which often requires on the order of 250 feet and with conventional horizontal drilling which can utilize on the order of 2,500 feet for a full 90 degree heel. Conventional horizontal drilling technologies operate at a scale 3 to 4 orders of magnitude larger than those of short radius lateral drilling technologies.

The process of “radial drilling” entails forming extended boreholes (e.g. at least 5 feet) in earthen formations that extend outward from a primary wellbore. These laterals may extend as short as 5 feet or they may extend beyond 50 feet. In radial drilling, the exit angle from the primary wellbore ranges from 45 degrees to slightly over 90 degrees and form a “radial borehole”. As one might imagine, radial boreholes entail extraordinarily high “build-angles” for the tools. That is, these build-angles are diametrically opposed to those found in conventional rig-based or coiled tubing-based horizontal drilling procedures. In these conventional applications, the tool string exits the wellbore at extremely shallow exit angles, typically no more than 3 to 5 degrees.

Radial drilling procedures typically entail the placement of a whipstock at a target depth inside the wellbore. Commonly, the whipstock has a sort of “J-path” that directs the small cutting tools around the tight radius. Sometimes the whipstock is run on the end of upset or production tubing. Radial drilling related tools and procedures can be used on open-hole completed or cased hole wells. If no opening is present in a cased well, access to the formation is sometimes gained by milling out a section of the metal well casing. More commonly, however, a specialized tool string is moved down the wellbore and are used to form a small hole in the casing, typically about 3/4″ to 1½″ in diameter. In known practices, the tools used to form the casing hole are then retracted and a separate formation-drilling tool is inserted downhole.

The formation-drilling tools are then directed by the whipstock toward the earthen formation or target zone (through the existing hole in the casing). Obviously, in open-hole completed wells, there is no need to cut the casing. Regardless of whether the well is cased or open hole completed, the tools are manipulated by some form of control-line. The control-line might be a wireline unit, a coil tubing unit (CTU) or jointed-tubing.

Known processes and current tools used for radial drilling are inherently inefficient when drilling out of cased-hole completed wells. Specifically, the current paradigm requires multiple downhole trips in order to run different tool strings. The core steps in current radial drilling procedures are as follows:

-   1) A tool string capable of cutting steel casing is connected to a     control-line and is lowered into the well. -   2) The tool string is tripped downhole to the pre-positioned     whipstock. -   3) The tool string is engaged to cut a hole in the wellbore casing. -   4) The tool string is then retraced back to the surface. -   5) The tool string is disconnected from the control-line and removed     from the wellbore. -   6) A second and separate formation drilling tool string is placed in     the wellbore and is connected to the control-line. -   7) The 2^(nd) tool string is tripped downhole to the whipstock. -   8) The 2^(nd) tool string is engaged to cut a lateral in the earthen     formation. -   9) The 2^(nd) tool string is then tripped backed to surface. -   10) Disconnected from the control line and removed from the well.

This process requires at least two different tool strings and two downhole trips to form a single lateral. If additional laterals are to be drilled, the whipstock is repositioned and the steps above are repeated.

Tools used in conventional coiled tubing side-track applications are not suited to making the tight radius at the bottom of the J-path. Moreover, their method of operations is different from radial drilling in that they essentially involve side-milling long slots rather than drilling precise holes in the casing (as is the case in radial drilling).

At present, in the art of radial drilling, no known technologies or disclosures are suitable for cutting both the casing and formation with a single tool and in a single tool string trip. The drill bit and/or drill string have to be designed to cut the steel casing or they have to be optimized for drilling the rock formation. For example, PDC inserts are excellent at cutting hard rock formations, but can easily chip and fail when used to cut steel casing. Because of the difficulty of cutting casing and formation with the same cutting head, known methods and apparatus for mechanical radial drilling have either focused their efforts on open hole completed wells or employ the laborious two-step process, described above. Known methods for mechanically cutting the hole in the casing do not even propose to eject drilling-fluid out of the casing cutting string, presumably because the practitioners never anticipated using those drill strings to also drill the formation itself. Without drilling fluid to cool the cutting faces on the cutting head and to wash the cuttings out of the lateral (and back to the wellbore), one cannot mechanically drill a lateral of any meaningful distance into a rock formation.

At present, single-step mechanical radial drilling from cased wells is not known. Either: a) the radial drilling procedure is only performed on an open-hole completed well, where one does not need to drill through casing; or b) an inefficient “two-step” process like that described above is performed.

When drilling the casing in the two-step process, typically some form of spade insert is used in the casing cutting drill-head. The spade inserts are most often made of a “softer” base metal that can resist shock loads (such as might occur if the bit stalls when cutting casing), and a hard, thin outer coating. While most of these inserts can reliably drill a single hole in the steel wellbore casing, often they cannot reliably drill multiple holes. Moreover, if one were to try using such a system to drill into a rock formation, especially abrasive ones like sandstone, the drill bit would quickly dull. The reason current radial drilling technologies cannot drill through cased wells and into formations originates from two reasons. First, the failure to provide fluid to the cutting head to cool the cutting bit and assure any hard coating remains intact is not presently practiced. And, second, the inherently poor bit stability due to their only having two cutting edges on a spade bit allows for the drill bit inserts to quickly dull.

A solution for mechanically drilling rock with a bit that does not appreciably dull is to use a poly crystal diamond (PDC) bit. PDC have exceptional durability and abrasion resistance and can drill all forms of rock, even granite. Unfortunately, known PDCs are not well suited for drilling through metal (casing) as they can easily fracture or chip. Thus, known PDCs do not present a viable solution for one-step radial drilling.

In light of the above shortcomings there is a need for apparatus and methods that are capable of reliably drilling a radial through casing and earthen formation with one and the same tool and in a single trip of a downhole drill string.

SUMMARY

This disclosure applies to radial drilling applications wherein lateral boreholes are mechanically drilled outward from an existing primary wellbore at between 45 to about 90 degrees. This disclosure provides a dual purpose radial drilling tool string capable of cutting casing, cement and rock in a single trip of a radial drilling tool string. Disclosed herein are both a method and apparatus for efficient mechanical drilling of radial boreholes outward from a wellbore.

BRIEF DESCRIPTION OF DRAWINGS

The accompanying views of the drawing are incorporated into and form a part of the specification to illustrate several aspects and examples of the present disclosure, wherein like reference numbers refer to like parts throughout the figures of the drawing. These figures together with the description serve to explain the general principles of the disclosure. The figures are only for the purpose of illustrating preferred and alternative examples of how the various aspects of the disclosure can be made and used and are not to be construed as limiting the disclosure to only the illustrated and described examples. The various advantages and features of the various aspects of the present disclosure will be apparent from a consideration of the figures.

FIG. 1A illustrates a control-line being used to manipulate a radial drilling tool string through a whipstock. The tool string consists of a flexible drill string with mechanical cutting head; and, in this instance a downhole motor controlled by coiled tubing. The dual purpose mechanical cutting head is about to cut through the steel well casing.

FIG. 1B illustrates the same system as FIG. 1A, except that the dual purpose mechanical drill string and cutting head have continued to drill a radial borehole deep into the formation. That is, the lateral borehole in the rock is being formed with the same tool string as was used to cut the steel well casing.

FIG. 2A illustrates a cutting head with three cutting inserts, one being long and two being short, and with four fluid exit ports. FIG. 2B illustrates a cross-sectional view along line B, showing the cutting head's long insert with chamfers on the bottom edge. FIG. 2C illustrates a cross-sectional view of FIG. 2A along line B, showing the two short cutting inserts in profile. The figure also depicts two of the fluid passageways that allow fluid to wash the cutting inserts.

FIG. 3A illustrates a cutting head that takes four cutting inserts, has four back-supports (one for each insert) and a single fluid exit located in the center of the cutting head. FIG. 3B is a cross-sectional of FIG. 3A and shows two of the four back-supports. FIG. 3C illustrates a cross-sectional view of FIG. 3A along line B. A single, long rounded cutting insert has been placed into the two seats along line B. The cutting insert thus divides the fluid flow exiting the head, as shown by arrows.

FIG. 4A illustrates a cutting head with three inserts placed and dividing a single, centrally located fluid passageway. FIG. 4B illustrates the apparatus of FIG. 4A in a cross-sectional view along line B and positioned inside of wellbore about to begin cutting the casing. Also shown is a flexible drill string that is connected to the cutting head. Inside of the flexible drill string is a hose and wire-rope both of which terminate in the cutting head. FIG. 4C illustrates the same moment of time as depicted in FIG. 4B but presents a profile view. Here we can see the flexible drill string and cutting head have been cut along line C of FIG. 4A, with the steel casing now evident in a vertical orientation.

FIG. 5A illustrates a horizontal cross-sectional view of the cutting head drilling through the wellbore casing. A cutting insert, like that in FIG. 4A, can be seen cutting the casing. Notably, the two sides of the insert are providing angular stability to the cutting head. FIG. 5B illustrates a vertical cross-sectional view of FIG. 5A. In this cross-sectional view, the two short inserts can be seen at the periphery and the one long one is seen at center (also in cross-section). Worth noting is the fact that the two short inserts provide lateral stability to the cutting head. That is, this cutting head does not tend to rock side-to-side nor up-and-down, due to the provision for multiple cutting inserts being in simultaneously contact with the face of the material being cut. FIG. 5C returns to the view of FIG. 5A but shows the dual purpose cutting head having cut through the steel casing and now proceeding to drill a lateral into rock. FIG. 5D shows the cutting head with its angular and lateral stability on account of the multiple cutting faces that are in simultaneous contact.

FIG. 6A shows a plan view of a cutting head with three inserts, three back-supports, and three peripherally located drilling fluid ports.

FIG. 6B illustrates four inserts positioned on a cutting head with a single center fluid exit port. Two inserts are positioned along the center line X while two additional inserts sit slightly off-center, so that their cutting edges are along centerline Y. FIG. 6C illustrates a profile view of the two inserts that are positioned along the centerline X of FIG. 6B showing. The inserts converge towards, but do not touch at the axis of rotation.

FIG. 6D illustrates a cutting head wherein the center of the cutting inserts that have been moved off the centerline and wherein the seats are “integral” to the body of the cutting head. A single fluid exit port provides for a single fluid stream (better evident in FIG. 6E) that is then divided into four flow streams by the inserts. FIG. 6E illustrates the body of the cutting head of FIGS. 6D and 6B. FIG. 6F illustrates varying thicknesses of the inserts of FIG. 6D, while FIG. 6G illustrates the back relief angle.

FIG. 7A through 7D illustrate a cutting head comprised of three inserts that define a pilot bit. There are two shorter inserts and one longer insert that reaches across the fluid exit port at the center along line M. The pilot bit feature is on the long insert, which spans the axis of rotation. FIG. 7D illustrates a profile view with the long pilot insert superimposed upon the two shorter outer inserts.

FIG. 8A illustrates a cutting head comprised of three rounded profile inserts, the long insert reaching across the fluid exit port, while the two periphery inserts do not intersect the fluid port. Besides sharing a common forward cutting profile, these rounded inserts also have a small radius on their bottom/trailing edge.

FIG. 9 illustrates a cutting head for radial drilling of casing and rock wherein the cutting edges are curved rather than linear (as is most often the case).

FIG. 10A through 10D illustrates another dual purpose radial drilling cutting head. Attached to the cutting head is a wire-rope, a hose used to convey fluid to the cutting head and the flexible drill string that drives (rotates) the cutting head. FIGS. 10A and 10B are shown without the inserts emplaced, while FIGS. 10C and 10D have the inserts positioned. In FIG. 10D, the single fluid flow exit port is seen being divided by the insert.

DETAILED DESCRIPTION

This disclosure presents an apparatus and method which allow a person to form a hole in wellbore casing and to then cut through cement and rock with a single trip of a “dual purpose” radial drilling apparatus. More specifically, with this disclosure one can eliminate the repetitive, time-consuming and costly steps of tripping one tool string downhole to form a hole in the wellbore casing and then tripping a separate tool string downhole to drill a radial borehole through the cement and into the surrounding earthen formation. Further, this disclosure enables multiple holes in the casing and radials in the rock formation to be made with a single drill string and in a single downhole trip of that drill string.

Typically, the drill string of this disclosure is run on a coiled tubing unit (CTU), as coiled tubing provides an efficient and economical method of supplying fluid power and controlling the position of the tool-sting downhole. However, this disclosure also allows the use of this dual purpose drill string on the end of a wireline unit, such as if using a downhole electric motor in place of a mud motor. In a notable difference with conventional coiled tubing side track jobs, the downhole motor remains inside of the wellbore during the radial drilling procedure. In yet other embodiments, the tool string is run on the end of jointed tubing or rod that can be rotated from the surface, such as by a power swivel.

The apparatus and method of this invention involves deploying a whipstock, which acts as a guide-path to direct the drill string and attached drill head outward from the wellbore. This technology is quite familiar to those in the industry. The whipstock can be positioned on the end of a tubing string, such as production tubing, and it can be locked into position in the wellbore by means of a packer or anchor.

Embodiments of the drill string of this disclosure comprise a motor, a flexible drive shaft comprising a hose and a mechanical cutting head. In certain embodiments, to provide fluid to the cutting head, the hose or conduit runs inside the flexible drive shaft and terminates at the cutting head. In other embodiments, the flexible drive shaft used to rotate the cutting head is circumscribes by the hose. The hose in fluid communication with pumping equipment and supplies fluid (drilling fluid) to the cutting head. The hose is affixed to the cutting head and terminated on its upper end at a location below the motor. In embodiments, a downhole motor is used, which may be a mud motor or an electric motor.

In embodiments the flexible drive shaft defines a series of individual segments that mate or nest with one another to transmit torque around the whipstock, while also supplying fluid to the cutting head by means of the hose. In other embodiments, the flexible drive shaft is defined by a series of link and joint that can transmit torque by virtue of pins which hold the series of links together. In yet other embodiments counter-wound springs or cables are used to achieve the flexible drive shaft. Certain embodiments of a flexible drive shaft are described in PTC Application WO2014039078 A1, U.S. Patent Application 20120067647 A1 and U.S. patent application Ser. No. 13/226,489, all incorporated in their entirely herein by their reference. As more evident in the prior citations, in embodiments, the cutting head mates with the flexible drive shaft via gears or teeth, while in other embodiments the cutting head is threaded or be pinned to the end of the flexible drive shaft, while in yet other embodiments the flexible drive shaft is affixed to the cutting head by brazing or crimping.

In certain embodiments, a wire rope runs the length of the flexible drive shaft inside of the hose and then the wire rope terminates at the cutting head. The wire rope is used to maintain tension on the flexible drive shaft. In embodiments, the wire rope is affixed on its lower end to the cutting head by means of a crimp that rest upon a shoulder in the cutting head, or which is pinned, threaded or brazed to the cutting head. The other end of the wire rope may terminate in a sub-assembly located above the flexible drive shaft and in which is placed a spring. The wire rope may terminate at a crimp or nut which rest atop the spring and can thereby provide tension.

In practice, the flexible drive shaft and attached cutting head transition around the whipstock and are then directed towards the wellbore casing, cement, and earthen formation (i.e. the rock) that is to be drilled. Pumping equipment is in fluid communication with the hose and cutting head assembly. The cutting head has one or more internal passageways and ports for the drilling fluid to exit the cutting head. The drilling fluid can be fluid, gas or a combination of the two. The drilling fluid cools the cutting edge and cutting faces and washes cuttings out of the lateral borehole. To drill a radial borehole one would engage the motor, rotate the drill string, pump fluid to and out the attached cutting head and advance the tool string so as to cut the casing and then the rock formation. Embodiments of this disclosure would drill laterals to a distance in excess of 5 feet to distances of over 100 feet.

In all embodiments, the dual purpose cutting head of this disclosure has three or more cutting faces positioned around its axis of rotation. Moreover, during drilling, at least three of these cutting faces are in contact with the material being cut. This is done in order to assure both angular and lateral stability of the cutting head during drilling. By stabilizing the cutting head in this fashion, the cutting edges will not dull quickly, as is the case with known radial drilling technologies, and one can thereby drill both steel casing and rock. The deliberate and simultaneous angular and lateral contact of the cutting head with the material being cut also reduces wear and tear on the drill string and to improve drilling rates of penetration (ROPs).

It is worth noting that this disclosure is not like conventional coiled tubing drilling or “side-tracking” procedures. Besides the radical difference in exit angles, discussed earlier, the two types of cutting heads form very different openings in the wellbore casing and do so by distinctively different principles of operation. In side-tracking operations, the extended opening in the casing is formed by a “milling” procedure, wherein the side of the cutting head is used to create the opening. By contrast, the apparatus of this disclosure literally “drills” the casing; and, it does so using the front of the drill bit. Evidence to the fact that the two procedures are fundamentally different is the fact that side-tracking produces a long, narrow slot in the casing, whereas this radial drilling procedure yields a round hole.

In embodiments the cutting head is shaped so that it is narrower at its mid-section than at its cutting end. This is done to allow the cutting head to pass around the tight radius of the whipstock. In embodiments the cutting head would have a mid-section that is at least 2.5% narrower in diameter than its cutting diameter—i.e. the diameter cut by the periphery cutting edges. In embodiments the cutting head would be at least 2.5% narrower in diameter at its mid-section than at its proximal and cutting end. That is, the profile of the cutting head would be generally “hour-glass” in shape.

Embodiments of the cutting head allow fluid to pass to the back of the cutting head and toward the flexible drill string by virtue of one or more notches that run along the periphery of the cutting head. In embodiments, one or more centralizers may be incorporated into the cutting head body to provide additional rearward stability to the cutting head. The centralizer may consist of pins or protrusions toward the aft end of the cutting head. These centralizers would form a diameter no less than 5% smaller than the cutting diameter.

Embodiments of the cutting head include cutting faces made of material(s) suitable to cutting not only cement and rock, but also steel or alloy casing. In embodiments, the cutting faces may be defined by cutting inserts. The material of the cutting inserts may be selected from one of the following: carbide, tungsten carbide, cubic boron nitrate (CBN), high speed tool steel and/or cemented carbides. In embodiments the aforementioned cutting face or cutting inserts are coated by another harder material, such as titanium nitride or similar coatings, which may be better able to resist wear and dulling.

In embodiments, the cutting edges of the cutting inserts are shaped and placed about the cutting head so at to be radially symmetrical about the cutting head. That is, they are spaced in equal phasing around the cutting head. In embodiments, the individual cutting inserts on a cutting head may have different cutting edge profiles. For example, they may have “notches”, “teeth” or “serrations” so as to better point-load the material being cut. In this fashion, only part of a given cutting edge may be in contact with the full face of the formation being cut. Whatever the individual cutting edge profiles of the cutting faces, when taken together, the various cutting edges on a single cutting head would allow for at least three of the cutting edges to be in simultaneous contact with the material being cut. Moreover, this disclosure also entails the placement of inserts on opposite halves of the cutting head, the three points of contact would not all be “on the same side” of the cutting head. By designing a radial drilling head in this fashion, one can assure angular and lateral stability in the cutting head during operation.

Discussed above and evident in the attached figures, in certain embodiments, the three or more cutting edges of this disclosure are defined by at least three cutting inserts. These cutting inserts sit in seats upon the cutting head. In embodiments, the inserts are affixed to the cutting head by screws, pins, brazing or epoxy. In other embodiments, the cutting head material and the shape of the cutting head itself define the cutting faces and cutting edges. For example, in certain embodiments, the whole cutting head is made of high-speed steel, in which case the cutting faces are defined by the cutting head and not separate cutting inserts. In embodiments where separate cutting inserts are used, the cutting head defines back-support members (or “back-supports”) against which the cutting inserts rest. The back-supports resist the torque applied on the cutting inserts during drilling. The cutting head also has seats into which the cutting inserts are placed and which resist the drive force (or weight on bit) that is applied during the drilling of casing and rock.

In embodiments the seats on the cutting head are not in full contact with the lower face of the cutting insert. That is, part of the lower portion of the insert may be unsupported as it rests in its seat. This feature allows the lower edge of a cutting insert to be in direct contact with the drilling-fluid exiting the cutting head. In embodiments, a lower face of one or more cutting inserts obstructs or divides the fluid exiting the cutting head. In embodiments, the cutting head defines only one “central” exit port, whose flow is divided by at least one cutting insert.

In embodiments at least two cutting inserts touch at the axis of rotation. In yet other embodiments, a single insert spans the axis of rotation and defines cutting edges on opposite sides of the insert. In yet other embodiments, the cutting inserts converge toward but not touch at the axis of rotation. In these embodiments, the cutting edges would converge to within a distance of no greater than 7% of the maximum diameter of the cutting head. This “proximal convergence” of the cutting edges toward the axis of rotation serves to reduce the drive thrust (or weight on bit) required to fracture or yield the material. This is an important feature for radial drilling applications wherein it can sometimes be difficult to attain the sufficiently high WOB due to the loss of weight from the tight heel of the whipstock.

In embodiments, the cutting faces would have a rake angle with respect to the plane perpendicular to the axis of rotation. That is, the cutting edges would have relief angles behind their cutting faces. In embodiments, the cutting faces would have a relief angle defined by a chamfer or radius on the trailing or bottom edge of the cutting insert. This relief angle helps prevent the inserts from snagging when retracting the cutting head out of the borehole.

In embodiments, the inserts may be set back or “offset” from a diameter of the cutting head. This may be done to position the actual cutting edges themselves either along the diameter or in close proximity to a diameter of the cutting head. In embodiments, the cutting edges are positioned within 0.050″ of a diameter of the cutting head.

In embodiments, the inserts have a straight cutting edge profile but the width of the insert varies along its length. That is, one portion of the insert may be narrower than another portion. For example, the portion of an insert that sits toward the middle of the cutting head may be narrower than the rest of that insert. In certain embodiments, the cutting edges are defined by curvilinear cutting edges rather than the more common linear cutting edges. Naturally, if the cutting edge is defined by a cutting insert, this would also mean that a portion of the cutting insert is curvilinear. It may also mean that the width of the insert varies over its length.

In all embodiments, the cutting head would have one or more passageways and one or more ports to allow drilling fluid to exit the cutting head. The drilling fluid allows for removal of cuttings and for lubrication and cooling of the cutting faces and cutting inserts. In embodiments, the cutting head would define a main central passageway wherein the fluid flow is split by one or more inserts. In certain embodiments the lower face of the cutting insert would be in direct contact with the fluid exiting the cutting head or would partially obstruct the fluid exiting the cutting head. In certain embodiments the fluid would exit the cutting head at or near its center so as to allow the fluid to cool and flush cuttings the entire length of the cutting face. Obviously, the drilling “fluid” may be fluid, gas or combinations thereof.

While the “dual purpose” apparatus of this disclosure produces the greatest improvement over current industry practices in cased hole wells, the drilling head of this disclosure, with its multiple points of contact is also well-suited to efficiently drilling rock in open-hole completed wells.

Notably, the radial drilling cutting head of this disclosure is capable of cutting wellbore casing, cement and earthen formation with minimal dulling due to: 1) the inherent stability of the at least three points in contact with the material being cut; 2) the selection of suitable cutting insert material; 3) the optional coatings; and 4) the provision for fluid to exit the cutting head. Moreover, the provision to provide additional aft stabilization or centralization of the cutting head can helps reduced the required WOB, improve drilling ROPs and reduce wear to the drill string.

This disclosure does not merely allow one hole in the casing and one lateral in the rock to be drilled on a tool string trip. Instead, because of the aforementioned provisions to reduce cutting head dulling and wear, multiple holes in the casing and multiple laterals in the formation can be drilled in that same downhole tool string trip. To accomplish this elusive yet very desirable objective, after drilling the first radial one would: 1) retract the drill string back through the whipstock and into the wellbore; 2) move the whipstock to a new location in the well; 3) set the optional anchor/packer; and, then 4) repeat the steps of drilling the casing and formation. In this fashion multiple radials can be drilled in one downhole trip of this dual-purpose drill string.

Now for a detailed description of the drawings, FIG. 1A illustrates a control-line (2) being used to manipulate a radial drilling tool string (8) through a whipstock (9), which is run on the end of upset tubing (3) and secured by an anchor (13). The tool string (8) consists of a flexible drill string (10) with a mechanical cutting head (11); and in this instance a downhole motor (6) controlled by coiled tubing (2). The mechanical cutting head (11) is about to cut through the steel wellbore casing (5). Also shown is a wellhead (5 b), a wellbore (7) and earthen formation (14).

FIG. 1B illustrates the same system as FIG. 1A, except that the flexible drill string (10) and cutting head (11) have cut through the wellbore casing (5) and has continued to drill a radial borehole (12) into the earthen formation (14). Unlike known radial drilling technologies the lateral borehole (12) is being formed with the same tool string (8) as the casing (5) cutting process.

FIG. 2A illustrates a cutting head (11) of this disclosure with one “long” insert (26) and two “short” inserts (24, 25), four back-supports (20) and four fluid exit ports (16) for ejection of drilling-fluid (shown by arrows). The direction of rotation is shown by the curved arrow at top. While there are only three cutting insert (24, 25, 26), there are four cutting edges (24 a, 25 a, 26 a, 26 b), two of which (26 a, 26 b) are on opposite sides of the long insert (26).

FIG. 2B illustrates a cross-section of FIG. 2A along the centerline B, which is positioned on the long cutting insert (26). Chamfers (28) have been created on the bottom, non-cutting edge (21) of the insert (26). This chamfer prevents the insert (26) from snagging on any materials (not shown) when the cutting head (11) is being pulled backwards.

FIG. 2C illustrates a cross-sectional view of FIG. 2A, this time the cross-section is along line C and the viewing area is from the bottom left of FIG. 2A. Line C intersects two of the fluid passageways (18 a, 18 b) within the cutting head (11). The long insert (26) can be seen at the center of the figure, while cutting insert (24) can be seen at left and cutting insert (25) at right and partially obstructed by the back-support (20 a). Also evident is the smaller diameter of the cutting head (11) around its mid-section (11 b) than its forward section (11 c), where the back-support (20) is positioned. One can see an internal passageways (18 b) extending out of back-support (20 a) supporting “short” cutting inserts (25). Chamfers (28) are visible at the bottom of the short inserts (24, 25).

FIG. 3A illustrates a cutting head (11) with four seats (22) for the placement of cutting inserts (not yet placed on the cutting head). Two (20 a, 20 b) of the four back-supports (20) are specifically labeled. There is a single fluid exit port (16) at the center of the cutting head (11).

FIG. 3B illustrates FIG. 3A in cross-section when cut along line B and viewed from the bottom. The inner fluid passageway (18) is evident as are the back-supports (20 a, 20 b). At this point, a single stream of drilling-fluid (shown by arrow) would exit the cutting head (11) from fluid passageway (18). The mid-section (11 b) of the cutting head (11) is narrower than the forward (11 c) and rear portions (11 d). FIG. 3C illustrates a cross-sectional view of FIG. 3A along line B, but this time, a long “rounded” cutting insert (30) has been placed upon the cutting head (11). The drilling-fluid (shown by arrows) exiting the inner-passageway (18) of the cutting head (11) is divided by insert (30).

FIG. 4A illustrates a cutting head (11) with four back-supports (20). Two cutting edges (24 a, 25 a) are formed by “short” inserts (24, 25); and, two additional cutting edges (26 a, 26 b) are formed by the one “long” insert (26). In addition, a center fluid exit port (16) that allows fluid to exit the cutting head (11), albeit the flow (exemplified by arrows) has been divided by the three inserts (24, 25, 26). Two lines, B and C, traverse the centerline of the cutting head (11).

FIG. 4B illustrates the apparatus of FIG. 4A in cross-section along line B positioned inside of and about to begin cutting wellbore casing (5). We also see that the cutting head (11) has been attached to a flexible drilling-string (10) and that a wire-rope (40) has been located inside of a hose (36) running the length of the flexible drill string (10). For purposes of clarity, the whipstock (not shown) used to position the flexible drill string (10) and cutting head (11), as seen in FIG. 1A, is not being shown here. The hose (36) is affixed to the cutting head (11). A crimp (38) with flow-through channels (38 b) has been affixed to the wire rope (40) and the crimp (38) cannot be retracted from the cutting head (11) because it rests upon a shoulder (42). Drilling-fluid flows (shown by arrows) can travel down the hose (36), through the flow-through channels (38 b) in the crimp (38) and out of the cutting head (11).

FIG. 4C illustrates the same moment of time as depicted in FIG. 4B but presents a profile view where the flexible drill string (10) and cutting head (11) have been cut along line C of FIG. 4A. Fluid (shown by arrows) flows down the flexible drill string (10) in the space between the hose (36) and wire rope (40). It then flows through the crimp (38) and out the cutting head (11). Also evident in this cross-sectional view is the wellbore casing (5), short inserts (24 and 25) of FIG. 4A and a cross-section of long insert (26).

FIG. 5A illustrates the apparatus of FIG. 4B after partial penetration of the steel wellbore casing (5). Unlike the shoulder (42) of FIG. 4B, the crimp (38) in this figure has been affixed to the cutting head (11) by threading (42 b). The tip (26 c) of the long cutting insert (26) is seen in the casing (5). Of note is the fact that both cutting edges (26 a, 26 b) are in firm contact with the casing (5), thereby providing angular stability to the cutting head (11).

FIG. 5B illustrates a profile view of the apparatus of FIG. 5A and at the same point in time. In this view, however, we see that cutting edges (24 a, 25 a) of the shorter inserts (24, 25) are also in firm contact with the steel casing (5), thus proving lateral stability to the cutting head (11). Thus, between FIG. 5A and 5B, all four cutting edges (24 a, 25 a, 26 a, 26 b) are in simultaneous contact with the steel casing (5) and hence the cutting head (11) is extremely well stabilized. FIG. 5C illustrates the beginning of a deep-reaching lateral (12) being drilled by the cutting head (11) and flexible drill string (10) of FIG. 5A after having penetrated the steel casing (5). This feat has been accomplished in the same tool string trip and with the same tools, unlike other radial drilling methods wherein multiple tool string and tool string trips are required. FIG. 5D provides an abstract view of cutting inserts (24, 25, 26) seen in FIG. 5C and shown about their axis of rotation (the curved arrow). This configuration of inserts (24, 25, 26) provide both angular and lateral stability.

FIG. 6A illustrates a plan view of a cutting head (11) with three inserts (48), back-supports (20) and periphery-located fluid exit ports (16). The fluid (shown by arrow) that exits the cutting head (11) never touches the lower edge (not shown) of the three cutting inserts (48). Instead the fluid exits through “unobstructed” ports (16).

The usual back-supports on the drilling-heads of FIG. 6B and 6D do not “stand above” the respective body of their cutting heads. Effectively, the usual seats for the inserts are simply a “notch” in the top of the main body. As such, the usual “back-support” found on the cutting head are depicted in these figures as one and the same as the cutting head itself. Discussed more fully, below, this is most evident in FIG. 6E, which shows the profile view of FIG. 6D along line B.

FIG. 6B illustrates two sets of cutting inserts (50 and 51) positioned on a cutting head (11). One set of inserts (51) are positioned along the centerline (shown by line X) while the other set of inserts (50) are positioned slightly off the centerline (shown by line Y). This has been done so the cutting edges (50 a, 50 b) of inserts (50) are positioned along the centerline (Y). Also evident is a fluid exit port (16) in the center of the cutting head (11) and a small gap (G) between the set of inserts (50 and 51). FIG. 6C illustrates a profile view of one set of inserts (51) of FIG. 6B along line X. The inserts (51) converge toward but do not meet (see gap G) at the apex (shown by dotted line).

FIG. 6D illustrates a cutting head (11) wherein the set of cutting inserts (52) have been moved off the centerline (shown by dotted lines). This has been done so that the cutting edges (52 b) of the inserts (52) are positioned along the centerlines. Also depicted is a fluid exit port (16) in the center of the cutting head (11), whose flow is split by the set of inserts (52). FIG. 6E illustrates the cutting head (11) of FIG. 6D along line D, but without the inserts (52) installed. A single fluid passageway (18) and back-supports (20), which do not protrude from the cutting head (11), can be seen. Effectively the inserts (not shown) sit in “notches” in the cutting head (11). That is, the back-supports (20) do not “extend above” the cutting head (11). FIG. 6f illustrates a plan view of a cutting insert (52) of FIG. 6D. The thickness of the insert (52) can vary along lines A, B and C, i.e. its center (A), mid-section (B) and outside (C). FIG. 6G illustrates an insert (52) of FIG. 6D in profile. Evident is a relief behind (52 e) behind the cutting face (52 c).

FIG. 7A illustrates a cutting head (11) comprised of three inserts (54 a, 54 b and 56) forming a pilot bit feature. The two short inserts (54 a and 54 b) cut the periphery. A long insert (56), which has the pilot bit feature (56 b), cuts the center; there is also a central fluid exit port (16) through the cutting head (11). FIG. 7B illustrates the profile view of the long insert (56) of FIG. 7A along line (M). Shown is the pilot bit feature (56 b) that allows for better ROP. FIG. 7C illustrates the profile of the two outer short inserts (54 a and 54 b) of FIG. 7A along line (N). FIG. 7D superimposes FIG. 7B upon FIG. 7C and shows how the outer inserts (54 a and 54 b) are a continuation of the profile cut by the insert (56). This allows for the cutting head (shown as 11 in FIG. 7A, to have four points of contact at all times with the material being cut allowing for heightened stability.

FIG. 8A illustrates a cutting head (11) wherein two smaller, outside inserts (58) have been moved off the center-line so that their cutting edges (58 q and 58 p) are positioned along lines Q and P, respectively. These two smaller inserts (58) help cut the periphery. The longer middle insert (60) remains on the centerline M and extends the full diameter of the cutting head (11). The rounded nature of the set of inserts (58 and 60) versus the typical “linear” profile (as exemplified in FIG. 7D) is evident in FIGS. 8B and 8C. FIG. 8B illustrates a profile view of the long cutting insert (60) of FIG. 8A which are positioned along line M. Depicted in this figure is the rounded nature of the cutting insert (60). FIG. 8C illustrates a profile view of the two short inserts (58) of FIG. 8A along line Q; this set of inserts (58) has the same cutting profile as insert (60) in FIG. 8B.

FIG. 9 illustrates a cutting head (11) for radial drilling applications wherein the set of cutting edges (63) on the inserts (62) are curved rather than linear. Also shown is a fluid exit port (16) positioned at the center of the cutting head (11).

FIG. 10A illustrates a cutting head (11) for radial drilling applications. The seats (22) for the cutting inserts are visible as are the back-supports (20); no inserts have yet been placed into the seats (22). A crimp (38) that is secured to a wire-rope (40) (not visible in this view) can be seen through the centrally-located fluid exit port (16) by which the drilling fluid, shown by dotted arrows, exits the cutting head (11). FIG. 10B illustrates a profile view of FIG. 10A. Evident are the back-supports (20), the cutting head (11), the flexible drill string (10), a hose (36) inside the flexible drill string (10), a wire rope (40) located inside the hose (36), a crimp (38) and pins (64) used to secure the wire rope (40) via the crimp (38) to the cutting head (11). In this view, fluid (shown by arrows) traverses through the hose (36), behind the pins (64) and out the top of the cutting head (11). FIG. 10C illustrates the cutting head (11) of FIG. 10A and 10B but with inserts (66 and 68) installed. There are two short inserts (66) and one long insert (68) which are positioned along a centerline. The inserts (66 and 68) rest against the back-supports (20) but partially obstruct the center fluid exit port (16). FIG. 10D illustrates a profile view of FIG. 10C along centerline C. In this figure the two pins (64) used to keep the crimp (38) from pulling out of the cutting head (11). Additionally, the one long insert (68) can be seen dividing the flow (shown by arrows) out of the cutting head (11). Also depicted is the flexible drill string (10), hose (36), wire-rope (40) and a fluid passageway (18) inside of the cutting head (11).

Embodiments of the present disclosure define a downhole drilling apparatus for cutting casing and rock when radial drilling defined by a cutting head having three or more cutting edges positioned around the cutting head axis of rotation, at least three of the cutting edges in continuous contact with the face of a material being cut, thereby providing lateral and angular stability to the cutting head, one or more internal fluid passageway within the cutting head and one or more orifices for ejecting drilling fluid out of the cutting head.

The apparatus can further include a passageway along the center of the cutting head for ejecting the fluid. Optionally the apparatus can further include a wire rope with a lower end and an upper end, the lower end of the wire rope positioned along the centerline of the cutting head and terminates in the cutting head and the upper end of the wire-rope terminates above a flexible portion of the drilling apparatus.

In an embodiment the apparatus can further include at least three inserts that define cutting edges and cutting faces, with the inserts positioned in seats upon the cutting head. In an embodiment the apparatus can further include cutting edges having reliefs behind their cutting faces. In an alternate embodiment the apparatus can further include each point along the cutting edges are positioned within a distance of 0.050″ inches from a diameter of the cutting head. In an embodiment the apparatus can further include wherein at least two of the cutting edges either meet at a point situated along the axis of rotation of the cutting head; or converge toward the axis of rotation to a distance that is less than 7% of the maximum diameter cut by the cutting head.

Optionally at least one insert has different widths along its length. Optionally the drilling fluid flow path is split by at least one insert. In an embodiment the apparatus can further include curvilinear cutting edges. In an embodiment the apparatus can further include a chamfer or radius on its cutting edges. In an embodiment the apparatus can further include the material of the cutting inserts can be selected from the group consisting of: carbide; tungsten carbide; cubic boron nitrate (CBN); high speed tool steel; cemented carbides, and combinations thereof. The apparatus can include an insert defines a lower face and at least part of said lower face being unsupported as the insert rests in its seat. In embodiments the apparatus has a lower face of the cutting insert that is in direct contact with drilling fluid exiting the cutting head.

Optionally the cutting head has a mid-section diameter less than 97.5% of the diameter of the cutting head maximum diameter defined by the cutting edges. In an embodiment the apparatus can further include a hard coating applied to the cutting edge to resist wear. In an embodiment the apparatus can further include the drilling apparatus attached to a flexible drill string comprising a hose running the length of the flexible drill string and said flexible drill string in fluid communication with pumping equipment. The flexible drill string can be selected from the group consisting of: a series of nesting drive segments, series of links with flexible joints connected by pinning mechanisms, a cable, a counter-wound cable, and combinations thereof.

An alternate embodiment is a system for radial drilling from a wellbore and through a casing, cement and earthen formation in a single trip. The system includes a whipstock positioned downhole and used to direct a mechanical drilling apparatus outward from the axis of the wellbore at between about 45 to slightly over 90 degrees, the mechanical drilling apparatus having a motor connected to a flexible drill string attached to a cutting head. The cutting head having three or more cutting edges positioned around the cutting head axis of rotation, at least three of the cutting edges in continuous contact with the face of a material being cut, thereby providing lateral and angular stability to the cutting head, one or more internal fluid passageway within the cutting head and one or more orifices for ejecting drilling fluid out of the cutting head. The flexible drill string in fluid communication with surface pumping equipment, the cutting head and flexible drill string capable of cutting at least 5 feet into an earthen formation.

An embodiment of the present disclosure is a method for radial drilling from a wellbore and through a casing, cement and earthen formation with a single mechanical drilling apparatus. The method includes placing a whipstock downhole to direct the mechanical drilling apparatus outward from the axis of a wellbore, pumping drilling-fluid down a conduit through a flexible drill string and out a cutting head. The cutting head having three or more cutting edges positioned around the cutting head axis of rotation, at least three of the cutting edges in continuous contact with the face of a material being cut, thereby providing lateral and angular stability to the cutting head, one or more internal fluid passageway within the cutting head and one or more orifices for ejecting drilling fluid out of the cutting head. Rotating the flexible drill string and attached cutting head to drill through a casing, cement and at least 5 feet into earthen formation.

An alternate embodiment of the present disclosure is a method for forming multiple radials from cased wells in a single trip of a downhole mechanical drilling apparatus. The method including securing a whipstock downhole to direct the mechanical drilling apparatus outward from the axis of a wellbore, pumping drilling fluid down a conduit through a flexible drill string and out a cutting head. The cutting head having three or more cutting edges positioned around the cutting head axis of rotation, at least three of the cutting edges in continuous contact with the face of a material being cut, thereby providing lateral and angular stability to the cutting head, one or more internal fluid passageway within the cutting head and one or more orifices for ejecting drilling fluid out of the cutting head. The method includes rotating the flexible drill string and attached cutting head to drill through a casing, cement and at least 5 feet into earthen formation, retracting the drill into the wellbore, rotating the whipstock and re-securing the whipstock at a second location in the wellbore and drilling a second radial through a casing, cement and into the earthen formation with the mechanical drilling apparatus.

The various embodiments of the present disclosure can be joined in combination with other embodiments of the disclosure and the listed embodiments herein are not meant to limit the disclosure. All combinations of various embodiments of the disclosure are enabled, even if not given in a particular example herein.

While illustrative embodiments have been depicted and described, modifications thereof can be made by one skilled in the art without departing from the scope of the disclosure. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Moreover, the indefinite articles “a” or “an”, as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents, the definitions that are consistent with this specification should be adopted. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee.

Depending on the context, all references herein to the “disclosure” may in some cases refer to certain specific embodiments only. In other cases it may refer to subject matter recited in one or more, but not necessarily all, of the claims. While the foregoing is directed to embodiments, versions and examples of the present disclosure, which are included to enable a person of ordinary skill in the art to make and use the disclosures when the information in this patent is combined with available information and technology, the disclosures are not limited to only these particular embodiments, versions and examples.

Numerous other modifications, equivalents, and alternatives, will become apparent to those skilled in the art once the above disclosure is fully appreciated. While embodiments of the disclosure have been shown and described, modifications thereof can be made by one skilled in the art without departing from the teachings of this disclosure. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the disclosure disclosed herein are possible and are within the scope of the disclosure.

Use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. It is intended that the following claims be interpreted to embrace all such modifications, equivalents, and alternatives where applicable. Other and further embodiments, versions and examples of the disclosure may be devised without departing from the basic scope thereof and the scope thereof is determined by the claims that follow. 

1. A downhole drilling apparatus for cutting casing and rock when radial drilling defined by a cutting head comprising: three or more cutting edges positioned around the cutting head axis of rotation; at least three of the cutting edges in continuous contact with the face of a material being cut, thereby providing lateral and angular stability to the cutting head; one or more internal fluid passageway within the cutting head; and, one or more orifices for ejecting drilling fluid out of the cutting head.
 2. The apparatus of claim 1, further comprising a passageway along the center of the cutting head for ejecting the fluid.
 3. The apparatus of claim 1, further comprising a wire rope with a lower end and an upper end, the lower end of the wire rope positioned along the centerline of the cutting head and terminates in the cutting head and the upper end of the wire-rope terminates above a flexible portion of the drilling apparatus.
 4. The apparatus of claim 1, further comprising at least three inserts that define cutting edges having a cutting face, said inserts partially located in seats upon the cutting head.
 5. The apparatus of claim 4, further comprising cutting edges having reliefs behind their cutting faces.
 6. The apparatus of claim 4, wherein each point along the cutting edges are positioned within a distance of 0.050″ inches from a diameter of the cutting head.
 7. The apparatus of claim 4, wherein at least two of the cutting edges either meet at a point situated along the axis of rotation of the cutting head; or converge toward the axis of rotation to a distance that is less than 7% of the maximum diameter cut by the cutting head.
 8. The apparatus of claim 4, wherein at least one insert having different widths along its length.
 9. The apparatus of claim 4, having a drilling fluid flow path that is split by at least one insert.
 10. The apparatus of claim 1, further comprising curvilinear cutting edges.
 11. The apparatus of claim 1, further comprising a chamfer or radius on its cutting edges.
 12. The apparatus of claim 4, wherein the material of the cutting inserts is selected from the group consisting of: carbide; tungsten carbide; cubic boron nitrate (CBN); high speed tool steel; cemented carbides, and combinations thereof.
 13. The apparatus of claim 4, wherein the insert defines a lower face and at least part of said lower face being unsupported as the insert rests in its seat.
 14. The apparatus of claim 4, wherein a lower face of the cutting insert is in direct contact with drilling fluid exiting the cutting head.
 15. The apparatus of claim 1, wherein the cutting head has a mid-section diameter less than 97.5% of the diameter of the cutting head maximum diameter defined by the cutting edges.
 16. The apparatus of claim 1, further comprising a hard coating applied to the cutting edge to resist wear.
 17. The apparatus of claim 1, further comprising the drilling apparatus attached to a flexible drill string comprising a hose running the length of the flexible drill string and said flexible drill string in fluid communication with pumping equipment.
 18. The apparatus of claim 17, wherein the flexible drill string is selected from the group consisting of: a series of nesting drive segments; series of links with flexible joints connected by pinning mechanisms; a cable; a counter-wound cable; and combinations thereof.
 19. A system for radial drilling from a wellbore and through a casing, cement and earthen formation in a single trip, said system comprising: a whipstock positioned downhole and used to direct a mechanical drilling apparatus outward from the axis of the wellbore at between about 45 to slightly over 90 degrees; the mechanical drilling apparatus comprising a motor connected to a flexible drill string attached to a cutting head defined in claim 1; the flexible drill string in fluid communication with surface pumping equipment; the cutting head and flexible drill string capable of cutting at least 5 feet into an earthen formation.
 20. A method for radial drilling from a wellbore and through a casing, cement and earthen formation with a single mechanical drilling apparatus, said method comprising: placing a whipstock downhole to direct the mechanical drilling apparatus outward from the axis of a wellbore; pumping drilling-fluid down a conduit through a flexible drill string and out a cutting head defined in claim 1; rotating the flexible drill string and attached cutting head to drill through a casing, cement and at least 5 feet into earthen formation.
 21. A method for forming multiple radials from cased wells in a single trip of a downhole mechanical drilling apparatus comprising: securing a whipstock downhole to direct the mechanical drilling apparatus outward from the axis of a wellbore; pumping drilling fluid down a conduit through a flexible drill string and out a cutting head defined in claim 1; rotating the flexible drill string and attached cutting head to drill through a casing, cement and at least 5 feet into earthen formation; retracting the drill into the wellbore, rotating the whipstock and re-securing the whipstock at a second location in the wellbore; and drilling a second radial through a casing, cement and into the earthen formation with the mechanical drilling apparatus. 